Most of the oil and gas wells drilled today are directional wells, meaning that their trajectory and target(s) depart substantially from a straight vertical well. A well trajectory is often described by a so-called survey table listing how the inclination and azimuth angles vary with measured depth. Inclination is the angular deviation from vertical, azimuth refers to the geographic direction, and measured depth refers to the along hole arc length from a selected datum position at the surface. Targets and wellbore trajectories may also be described by Cartesian coordinates, normally called northing, easting, and vertical depth.
Directional drilling is the technique of drilling a well so that its path closely follows the planned wellbore trajectory. Poor directional control can lead to many problems, such as reduced production rates of hydrocarbons when the target is missed, and excessive friction (torque and drag) if the wellbore is not smooth but crooked with a high tortuosity. Since time and costs are important factors in drilling, the challenge in directional drilling is to combine accurate trajectory control with a high rate of penetration.
There are several techniques for controlling the wellbore path during drilling. A relatively new group of systems, called rotary steerable systems (RSS), have in common that they provide directional control while rotating the string. Because these systems are quite sophisticated and expensive, they still have a limited marked share.
A common method, which has been used for many decades and is still widely used because of its relatively low cost, is sliding drilling with a steerable motor assembly. As the name indicates, this is a technique where the string is not rotated but slid into the well as the bit penetrates the formation. The bit is powered and rotated by a mud motor which can be either a positive displacement motor or a turbine motor driven by the drilling fluid pumped through the drill string. Directional control is provided by a bend often integrated in the motor housing. The direction of the bend, and of the bit rotation axis, is called the tool face. In a vertical wellbore section, the tool face determines the geographic azimuth direction, while in a deviated wellbore section, the tool face represents a vector, like the small handle of a circular watch. As two examples, a tool face pointing upwards (12 o'clock position) will build (increase) the inclination without changing the azimuth direction, while the 9 o'clock tool face position represents a pure left turn. Tool face is therefore a unit vector describing the desired direction of the wellbore curvature, perpendicular to the current tangent vector of the wellbore axis. The magnitude of the curvature depends on many variables, such as the bend angle, the distance from the bit to the bend, stabilizer positions, the flexural rigidity of the bottom hole assembly (BHA) and even the tool face.
Sliding drilling is most often used together with a measurement-while-drilling (MWD) tool placed above and close to the drilling motor. This MWD tool measures, by means of accelerometers and magnetometers, the inclination and the azimuth angles of the tool itself, and the tool face angle. These measurement data are normally transmitted to surface by mud pulse telemetry to provide the necessary feedback to the directional driller, who is the person responsible for keeping the wellbore close to the planned trajectory. The low transmission bandwidth provided by mud pulse telemetry makes the measurement rates relatively slow, typically one measurement per 30 seconds.
A special challenge with sliding drilling is the reactive twist of the string arising from a typical bit torque. As an example, a 3000 m long section of standard 5-inch drill pipes exposed to a typical bit torque of 5 kNm is twisted about 2.4 turns. This implies that a relatively small change in bit torque can cause a significant and undesired change in the tool face. The wellbore friction along the string will hinder an immediate twist response, but after some time, typically 1-30 minutes but strongly dependent on the penetration rate and the string length, the axial motion of the string will cause the new bit torque to progress up the string. The tool face, the total twist, and the average string torque will asymptotically reach their equilibrium values. The dynamics of this reactive twist is discussed in some detail below.
Common practice today is that when the directional driller has established a desired and stable tool face, the driller controls the tool face indirectly by a differential pressure control. This is a well-known technique utilizing the fact that the pressure drop across the mud motor is nearly proportional to the motor torque load. An increase of the mud motor pressure will, after some time delay, be seen at the surface as an increase of the pump pressure. The pump pressure is most often measured at the standpipe at rig floor but it is approximately equal to the pump discharge pressure. When a drop in this pump pressure is observed, the string is lowered to give a higher bit load and thereby also a higher torque and pressure drop across the mud motor. Bit load is here defined as the mechanical compression force between the bit and the formation, commonly called weight on bit (WOB) in the drilling industry. Similarly, bit torque denotes the resulting torque between bit and formation, commonly called torque on bit (TOB).
There exist several automatic control systems, called diff-P auto drillers, which control the string motion in a way that keeps the differential pump pressure fairly constant and close to a set point value.
The main drawbacks of common practice of controlling tool face by sliding drilling are:                The possibilities for increasing the bit load and improving the drilling rate is very limited, because tool face often has the highest priority. This limitation often leads to a poor overall drilling rate, much lower than drilling rates obtained during the rotary drilling mode.        The resulting wellbore curvature produced by a constant tool face is often higher than maximum curvature of the planned trajectory, to provide a necessary regulation margin. To keep the wellbore close to the planned trajectory the driller must therefore toggle between sliding mode and rotary mode. In the latter case the drill string is rotated at a relatively high speed to nullify the directional effect of the tool face.        The toggling between sliding and rotary modes deteriorates the wellbore smoothness, especially if the toggling depth intervals are long.        It often takes a long time to establish a correct and stable tool face in the sliding mode after a rotary session and after a connection when a new piece of pipe is added to the string.        High and variable axial wellbore friction makes it difficult to control the bit load and the bit torque from surface. In order to avoid high load peaks with a resulting risk of overloading and stalling of the mud motor, the average bit load must be kept relatively low, substantially lower than the bit and mud motor capacity.        
In the rotary mode, the bit gets a higher speed equal to the sum of the string and the mud motor rotation speeds. This increased bit speed only partially explains why the rotary mode most often produces much higher rates of penetration than the sliding mode. The most important explanation is that rotary drilling allows a higher and better-controlled bit load.
Exemplary embodiments of the claimed invention are disclosed in the description below. The invention is defined by the claim which follow the description.
The figures discussed in the following, and in particular FIGS. 1 and 3, are shown schematically and simplified. The various features in the drawings may not be drawn to scale